SB2365sam001 98TH GENERAL ASSEMBLY

Sen. Don Harmon

Filed: 4/15/2013

 

 


 

 


 
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1
AMENDMENT TO SENATE BILL 2365

2    AMENDMENT NO. ______. Amend Senate Bill 2365 by replacing
3everything after the enacting clause with the following:
 
4    "Section 5. The Illinois Finance Authority Act is amended
5by changing Section 825-65 as follows:
 
6    (20 ILCS 3501/825-65)
7    Sec. 825-65. Clean Coal, Coal, Energy Efficiency, and
8Renewable Energy Project Financing.
9    (a) Findings and declaration of policy.
10        (i) It is hereby found and declared that Illinois has
11    abundant coal resources and, in some areas of Illinois, the
12    demand for power exceeds the generating capacity.
13    Incentives to encourage the construction of coal-fueled
14    electric generating plants in Illinois to ensure power
15    generating capacity into the future and to advance clean
16    coal technology and the use of Illinois coal are in the

 

 

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1    best interests of all of the citizens of Illinois.
2        (ii) It is further found and declared that Illinois has
3    abundant potential and resources to develop renewable
4    energy resource projects and that there are many
5    opportunities to invest in cost-effective energy
6    efficiency projects throughout the State. The development
7    of those projects will create jobs and investment as well
8    as decrease environmental impacts and promote energy
9    independence in Illinois. Accordingly, the development of
10    those projects is in the best interests of all of the
11    citizens of Illinois.
12        (iii) The Authority is authorized to issue bonds to
13    help finance Clean Coal, Coal, Energy Efficiency, and
14    Renewable Energy projects pursuant to this Section.
15    (b) Definitions.
16        (i) "Clean Coal Project" means (A) "clean coal
17    facility", as defined in Section 1-10 of the Illinois Power
18    Agency Act; (B) "clean coal SNG facility", as defined in
19    Section 1-10 of the Illinois Power Agency Act; (C)
20    transmission lines and associated equipment that transfer
21    electricity from points of supply to points of delivery for
22    projects described in this subsection (b); (D) pipelines or
23    other methods to transfer carbon dioxide from the point of
24    production to the point of storage or sequestration for
25    projects described in this subsection (b); or (E) projects
26    to provide carbon abatement technology for existing

 

 

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1    generating facilities.
2        (ii) "Coal Project" means new electric generating
3    facilities or new gasification facilities, as defined in
4    Section 605-332 of the Department of Commerce and Economic
5    Opportunity Law of the Civil Administrative Code of
6    Illinois, which may include mine-mouth power plants,
7    projects that employ the use of clean coal technology,
8    projects to provide scrubber technology for existing
9    energy generating plants, or projects to provide electric
10    transmission facilities or new gasification facilities.
11        (iii) "Energy Efficiency Project" means measures that
12    reduce the amount of electricity or natural gas required to
13    achieve a given end use, consistent with Section 1-10 of
14    the Illinois Power Agency Act. "Energy Efficiency Project"
15    also includes measures that reduce the total Btus of
16    electricity and natural gas needed to meet the end use or
17    uses consistent with Section 1-10 of the Illinois Power
18    Agency Act.
19        (iv) "Renewable Energy Project" means (A) a project
20    that uses renewable energy resources, as defined in Section
21    1-10 of the Illinois Power Agency Act; (B) a project that
22    uses environmentally preferable technologies and practices
23    that result in improvements to the production of renewable
24    fuels, including but not limited to, cellulosic
25    conversion, water and energy conservation, fractionation,
26    alternative feedstocks, or reduced green house gas

 

 

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1    emissions; (C) transmission lines and associated equipment
2    that transfer electricity from points of supply to points
3    of delivery for projects described in this subsection (b);
4    or (D) projects that use technology for the storage of
5    renewable energy, including, without limitation, the use
6    of battery or electrochemical storage technology for
7    mobile or stationary applications.
8    (c) Creation of reserve funds. The Authority may establish
9and maintain one or more reserve funds to enhance bonds issued
10by the Authority for a Clean Coal Project, a Coal Project, an
11Energy Efficiency Project, or a Renewable Energy Project. There
12may be one or more accounts in these reserve funds in which
13there may be deposited:
14        (1) any proceeds of the bonds issued by the Authority
15    required to be deposited therein by the terms of any
16    contract between the Authority and its bondholders or any
17    resolution of the Authority;
18        (2) any other moneys or funds of the Authority that it
19    may determine to deposit therein from any other source; and
20        (3) any other moneys or funds made available to the
21    Authority. Subject to the terms of any pledge to the owners
22    of any bonds, moneys in any reserve fund may be held and
23    applied to the payment of principal, premium, if any, and
24    interest of such bonds.
25    (d) Powers and duties. The Authority has the power:
26        (1) To issue bonds in one or more series pursuant to

 

 

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1    one or more resolutions of the Authority for any Clean Coal
2    Project, Coal Project, Energy Efficiency Project, or
3    Renewable Energy Project authorized under this Section,
4    within the authorization set forth in subsection (e).
5        (2) To provide for the funding of any reserves or other
6    funds or accounts deemed necessary by the Authority in
7    connection with any bonds issued by the Authority.
8        (3) To pledge any funds of the Authority or funds made
9    available to the Authority that may be applied to such
10    purpose as security for any bonds or any guarantees,
11    letters of credit, insurance contracts or similar credit
12    support or liquidity instruments securing the bonds.
13        (4) To enter into agreements or contracts with third
14    parties, whether public or private, including, without
15    limitation, the United States of America, the State or any
16    department or agency thereof, to obtain any
17    appropriations, grants, loans or guarantees that are
18    deemed necessary or desirable by the Authority. Any such
19    guarantee, agreement or contract may contain terms and
20    provisions necessary or desirable in connection with the
21    program, subject to the requirements established by the
22    Act.
23        (5) To exercise such other powers as are necessary or
24    incidental to the foregoing.
25    (e) Clean Coal Project, Coal Project, Energy Efficiency
26Project, and Renewable Energy Project bond authorization and

 

 

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1financing limits. In addition to any other bonds authorized to
2be issued under Sections 801-40(w), 825-60, 830-25 and 845-5,
3the Authority may have outstanding, at any time, bonds for the
4purpose enumerated in this Section 825-65 in an aggregate
5principal amount that shall not exceed $3,000,000,000, subject
6to the following limitations: (i) up to $300,000,000 may be
7issued to finance projects, as described in clause (C) of
8subsection (b)(i) and clause (C) of subsection (b)(iv) of this
9Section 825-65; (ii) up to $500,000,000 may be issued to
10finance projects, as described in clauses (D) and (E) of
11subsection (b)(i) of this Section 825-65; (iii) up to
12$2,000,000,000 may be issued to finance Clean Coal Projects, as
13described in clauses (A) and (B) of subsection (b)(i) of this
14Section 825-65 and Coal Projects, as described in subsection
15(b)(ii) of this Section 825-65; and (iv) up to $2,000,000,000
16may be issued to finance Energy Efficiency Projects, as
17described in subsection (b)(iii) of this Section 825-65 and
18Renewable Energy Projects, as described in clauses (A), (B),
19and (D) of subsection (b)(iii) of this Section 825-65. An
20application for a loan financed from bond proceeds from a
21borrower or its affiliates for a Clean Coal Project, a Coal
22Project, Energy Efficiency Project, or a Renewable Energy
23Project may not be approved by the Authority for an amount in
24excess of $450,000,000 for any borrower or its affiliates.
25These bonds shall not constitute an indebtedness or obligation
26of the State of Illinois and it shall be plainly stated on the

 

 

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1face of each bond that it does not constitute an indebtedness
2or obligation of the State of Illinois, but is payable solely
3from the revenues, income or other assets of the Authority
4pledged therefor.
5    (f) The bonding authority granted under this Section is in
6addition to and not limited by the provisions of Section 845-5.
7(Source: P.A. 95-470, eff. 8-27-07; 96-103, eff. 1-1-10;
896-817, eff. 1-1-10.)
 
9    Section 10. The Illinois Power Agency Act is amended by
10changing Section 1-10 as follows:
 
11    (20 ILCS 3855/1-10)
12    Sec. 1-10. Definitions.
13    "Agency" means the Illinois Power Agency.
14    "Agency loan agreement" means any agreement pursuant to
15which the Illinois Finance Authority agrees to loan the
16proceeds of revenue bonds issued with respect to a project to
17the Agency upon terms providing for loan repayment installments
18at least sufficient to pay when due all principal of, interest
19and premium, if any, on those revenue bonds, and providing for
20maintenance, insurance, and other matters in respect of the
21project.
22    "Authority" means the Illinois Finance Authority.
23    "Clean coal facility" means an electric generating
24facility that uses primarily coal as a feedstock and that

 

 

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1captures and sequesters carbon dioxide emissions at the
2following levels: at least 50% of the total carbon dioxide
3emissions that the facility would otherwise emit if, at the
4time construction commences, the facility is scheduled to
5commence operation before 2016, at least 70% of the total
6carbon dioxide emissions that the facility would otherwise emit
7if, at the time construction commences, the facility is
8scheduled to commence operation during 2016 or 2017, and at
9least 90% of the total carbon dioxide emissions that the
10facility would otherwise emit if, at the time construction
11commences, the facility is scheduled to commence operation
12after 2017. The power block of the clean coal facility shall
13not exceed allowable emission rates for sulfur dioxide,
14nitrogen oxides, carbon monoxide, particulates and mercury for
15a natural gas-fired combined-cycle facility the same size as
16and in the same location as the clean coal facility at the time
17the clean coal facility obtains an approved air permit. All
18coal used by a clean coal facility shall have high volatile
19bituminous rank and greater than 1.7 pounds of sulfur per
20million btu content, unless the clean coal facility does not
21use gasification technology and was operating as a conventional
22coal-fired electric generating facility on June 1, 2009 (the
23effective date of Public Act 95-1027).
24    "Clean coal SNG brownfield facility" means a facility that
25(1) has commenced construction by July 1, 2015 on an urban
26brownfield site in a municipality with at least 1,000,000

 

 

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1residents; (2) uses a gasification process to produce
2substitute natural gas; (3) uses coal as at least 50% of the
3total feedstock over the term of any sourcing agreement with a
4utility and the remainder of the feedstock may be either
5petroleum coke or coal, with all such coal having a high
6bituminous rank and greater than 1.7 pounds of sulfur per
7million Btu content unless the facility reasonably determines
8that it is necessary to use additional petroleum coke to
9deliver additional consumer savings, in which case the facility
10shall use coal for at least 35% of the total feedstock over the
11term of any sourcing agreement; and (4) captures and sequesters
12at least 85% of the total carbon dioxide emissions that the
13facility would otherwise emit.
14    "Clean coal SNG facility" means a facility that uses a
15gasification process to produce substitute natural gas, that
16sequesters at least 90% of the total carbon dioxide emissions
17that the facility would otherwise emit, that uses at least 90%
18coal as a feedstock, with all such coal having a high
19bituminous rank and greater than 1.7 pounds of sulfur per
20million btu content, and that has a valid and effective permit
21to construct emission sources and air pollution control
22equipment and approval with respect to the federal regulations
23for Prevention of Significant Deterioration of Air Quality
24(PSD) for the plant pursuant to the federal Clean Air Act;
25provided, however, a clean coal SNG brownfield facility shall
26not be a clean coal SNG facility.

 

 

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1    "Commission" means the Illinois Commerce Commission.
2    "Costs incurred in connection with the development and
3construction of a facility" means:
4        (1) the cost of acquisition of all real property,
5    fixtures, and improvements in connection therewith and
6    equipment, personal property, and other property, rights,
7    and easements acquired that are deemed necessary for the
8    operation and maintenance of the facility;
9        (2) financing costs with respect to bonds, notes, and
10    other evidences of indebtedness of the Agency;
11        (3) all origination, commitment, utilization,
12    facility, placement, underwriting, syndication, credit
13    enhancement, and rating agency fees;
14        (4) engineering, design, procurement, consulting,
15    legal, accounting, title insurance, survey, appraisal,
16    escrow, trustee, collateral agency, interest rate hedging,
17    interest rate swap, capitalized interest, contingency, as
18    required by lenders, and other financing costs, and other
19    expenses for professional services; and
20        (5) the costs of plans, specifications, site study and
21    investigation, installation, surveys, other Agency costs
22    and estimates of costs, and other expenses necessary or
23    incidental to determining the feasibility of any project,
24    together with such other expenses as may be necessary or
25    incidental to the financing, insuring, acquisition, and
26    construction of a specific project and starting up,

 

 

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1    commissioning, and placing that project in operation.
2    "Department" means the Department of Commerce and Economic
3Opportunity.
4    "Director" means the Director of the Illinois Power Agency.
5    "Demand-response" means measures that decrease peak
6electricity demand or shift demand from peak to off-peak
7periods.
8    "Distributed renewable energy generation device" means a
9device that is:
10        (1) powered by wind, solar thermal energy,
11    photovoltaic cells and panels, biodiesel, crops and
12    untreated and unadulterated organic waste biomass, tree
13    waste, and hydropower that does not involve new
14    construction or significant expansion of hydropower dams;
15        (2) interconnected at the distribution system level of
16    either an electric utility as defined in this Section, an
17    alternative retail electric supplier as defined in Section
18    16-102 of the Public Utilities Act, a municipal utility as
19    defined in Section 3-105 of the Public Utilities Act, or a
20    rural electric cooperative as defined in Section 3-119 of
21    the Public Utilities Act;
22        (3) located on the customer side of the customer's
23    electric meter and is primarily used to offset that
24    customer's electricity load; and
25        (4) limited in nameplate capacity to no more than 2,000
26    kilowatts.

 

 

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1    "Energy efficiency" means measures that reduce the amount
2of electricity or natural gas required to achieve a given end
3use. "Energy efficiency" also includes measures that reduce the
4total Btus of electricity and natural gas needed to meet the
5end use or uses.
6    "Electric utility" has the same definition as found in
7Section 16-102 of the Public Utilities Act.
8    "Facility" means an electric generating unit or a
9co-generating unit that produces electricity along with
10related equipment necessary to connect the facility to an
11electric transmission or distribution system.
12    "Governmental aggregator" means one or more units of local
13government that individually or collectively procure
14electricity to serve residential retail electrical loads
15located within its or their jurisdiction.
16    "Local government" means a unit of local government as
17defined in Section 1 of Article VII of the Illinois
18Constitution.
19    "Municipality" means a city, village, or incorporated
20town.
21    "Person" means any natural person, firm, partnership,
22corporation, either domestic or foreign, company, association,
23limited liability company, joint stock company, or association
24and includes any trustee, receiver, assignee, or personal
25representative thereof.
26    "Project" means the planning, bidding, and construction of

 

 

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1a facility.
2    "Public utility" has the same definition as found in
3Section 3-105 of the Public Utilities Act.
4    "Real property" means any interest in land together with
5all structures, fixtures, and improvements thereon, including
6lands under water and riparian rights, any easements,
7covenants, licenses, leases, rights-of-way, uses, and other
8interests, together with any liens, judgments, mortgages, or
9other claims or security interests related to real property.
10    "Renewable energy credit" means a tradable credit that
11represents the environmental attributes of a certain amount of
12energy produced from a renewable energy resource.
13    "Renewable energy resources" includes energy and its
14associated renewable energy credit or renewable energy credits
15from wind, solar thermal energy, photovoltaic cells and panels,
16biodiesel, anaerobic digestion, crops and untreated and
17unadulterated organic waste biomass, tree waste, hydropower
18that does not involve new construction or significant expansion
19of hydropower dams, and other alternative sources of
20environmentally preferable energy. For purposes of this Act,
21landfill gas produced in the State is considered a renewable
22energy resource. "Renewable energy resources" does not include
23the incineration or burning of tires, garbage, general
24household, institutional, and commercial waste, industrial
25lunchroom or office waste, landscape waste other than tree
26waste, railroad crossties, utility poles, or construction or

 

 

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1demolition debris, other than untreated and unadulterated
2waste wood.
3    "Revenue bond" means any bond, note, or other evidence of
4indebtedness issued by the Authority, the principal and
5interest of which is payable solely from revenues or income
6derived from any project or activity of the Agency.
7    "Sequester" means permanent storage of carbon dioxide by
8injecting it into a saline aquifer, a depleted gas reservoir,
9or an oil reservoir, directly or through an enhanced oil
10recovery process that may involve intermediate storage,
11regardless of whether these activities are conducted by a clean
12coal facility, a clean coal SNG facility, a clean coal SNG
13brownfield facility, or a party with which a clean coal
14facility, clean coal SNG facility, or clean coal SNG brownfield
15facility has contracted for such purposes.
16    "Sourcing agreement" means (i) in the case of an electric
17utility, an agreement between the owner of a clean coal
18facility and such electric utility, which agreement shall have
19terms and conditions meeting the requirements of paragraph (3)
20of subsection (d) of Section 1-75, (ii) in the case of an
21alternative retail electric supplier, an agreement between the
22owner of a clean coal facility and such alternative retail
23electric supplier, which agreement shall have terms and
24conditions meeting the requirements of Section 16-115(d)(5) of
25the Public Utilities Act, and (iii) in case of a gas utility,
26an agreement between the owner of a clean coal SNG brownfield

 

 

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1facility and the gas utility, which agreement shall have the
2terms and conditions meeting the requirements of subsection
3(h-1) of Section 9-220 of the Public Utilities Act.
4    "Substitute natural gas" or "SNG" means a gas manufactured
5by gasification of hydrocarbon feedstock, which is
6substantially interchangeable in use and distribution with
7conventional natural gas.
8    "Total resource cost test" or "TRC test" means a standard
9that is met if, for an investment in energy efficiency or
10demand-response measures, the benefit-cost ratio is greater
11than one. The benefit-cost ratio is the ratio of the net
12present value of the total benefits of the program to the net
13present value of the total costs as calculated over the
14lifetime of the measures. A total resource cost test compares
15the sum of avoided electric utility costs, representing the
16benefits that accrue to the system and the participant in the
17delivery of those efficiency measures, as well as other
18quantifiable societal benefits, including avoided natural gas
19utility costs, to the sum of all incremental costs of end-use
20measures that are implemented due to the program (including
21both utility and participant contributions), plus costs to
22administer, deliver, and evaluate each demand-side program, to
23quantify the net savings obtained by substituting the
24demand-side program for supply resources. In calculating
25avoided costs of power and energy that an electric utility
26would otherwise have had to acquire, reasonable estimates shall

 

 

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1be included of financial costs likely to be imposed by future
2regulations and legislation on emissions of greenhouse gases.
3(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09;
496-784, eff. 8-28-09; 96-1000, eff. 7-2-10; 97-96, eff.
57-13-11; 97-239, eff. 8-2-11; 97-491, eff. 8-22-11; 97-616,
6eff. 10-26-11; 97-813, eff. 7-13-12.)
 
7    Section 15. The Public Utilities Act is amended by changing
8Sections 8-103 and 8-104 as follows:
 
9    (220 ILCS 5/8-103)
10    Sec. 8-103. Energy efficiency and demand-response
11measures.
12    (a) It is the policy of the State that electric utilities
13are required to use cost-effective energy efficiency and
14demand-response measures to reduce delivery load. Requiring
15investment in cost-effective energy efficiency and
16demand-response measures will reduce direct and indirect costs
17to consumers by decreasing environmental impacts and by
18avoiding or delaying the need for new generation, transmission,
19and distribution infrastructure. It serves the public interest
20to allow electric utilities to recover costs for reasonably and
21prudently incurred expenses for energy efficiency and
22demand-response measures. As used in this Section,
23"cost-effective" means that the measures satisfy the total
24resource cost test. The low-income measures described in

 

 

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1subsection (f)(4) of this Section shall not be required to meet
2the total resource cost test. For purposes of this Section, the
3terms "energy-efficiency", "demand-response", "electric
4utility", and "total resource cost test" shall have the
5meanings set forth in the Illinois Power Agency Act. For
6purposes of this Section, the amount per kilowatthour means the
7total amount paid for electric service expressed on a per
8kilowatthour basis. For purposes of this Section, the total
9amount paid for electric service includes without limitation
10estimated amounts paid for supply, transmission, distribution,
11surcharges, and add-on-taxes.
12    (b) Electric utilities shall implement cost-effective
13energy efficiency measures to meet the following incremental
14annual energy savings goals:
15        (1) 0.2% of energy delivered in the year commencing
16    June 1, 2008;
17        (2) 0.4% of energy delivered in the year commencing
18    June 1, 2009;
19        (3) 0.6% of energy delivered in the year commencing
20    June 1, 2010;
21        (4) 0.8% of energy delivered in the year commencing
22    June 1, 2011;
23        (5) 1% of energy delivered in the year commencing June
24    1, 2012;
25        (6) 1.4% of energy delivered in the year commencing
26    June 1, 2013;

 

 

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1        (7) 1.8% of energy delivered in the year commencing
2    June 1, 2014; and
3        (8) 2% of energy delivered in the year commencing June
4    1, 2015 and each year thereafter.
5    Electric utilities may comply with this subsection (b) by
6meeting the annual incremental savings goal in the applicable
7year or by showing that total savings associated with measures
8implemented on or after May 31, 2014 were equal to the sum of
9each annual incremental savings requirement on or after June 1,
102014 through the end of the applicable year.
11    (c) Electric utilities shall implement cost-effective
12demand-response measures to reduce peak demand by 0.1% over the
13prior year for eligible retail customers, as defined in Section
1416-111.5 of this Act, and for customers that elect hourly
15service from the utility pursuant to Section 16-107 of this
16Act, provided those customers have not been declared
17competitive. This requirement commences June 1, 2008 and
18continues for 10 years.
19    (d) Notwithstanding the requirements of subsections (b)
20and (c) of this Section, an electric utility shall reduce the
21amount of energy efficiency and demand-response measures
22implemented over in any 3-year period single year by an amount
23necessary to limit the estimated average annual increase in the
24amounts paid by retail customers in connection with electric
25service due to the cost of those measures to:
26        (1) in 2008, no more than 0.5% of the amount paid per

 

 

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1    kilowatthour by those customers during the year ending May
2    31, 2007;
3        (2) in 2009, the greater of an additional 0.5% of the
4    amount paid per kilowatthour by those customers during the
5    year ending May 31, 2008 or 1% of the amount paid per
6    kilowatthour by those customers during the year ending May
7    31, 2007;
8        (3) in 2010, the greater of an additional 0.5% of the
9    amount paid per kilowatthour by those customers during the
10    year ending May 31, 2009 or 1.5% of the amount paid per
11    kilowatthour by those customers during the year ending May
12    31, 2007;
13        (4) in 2011, the greater of an additional 0.5% of the
14    amount paid per kilowatthour by those customers during the
15    year ending May 31, 2010 or 2% of the amount paid per
16    kilowatthour by those customers during the year ending May
17    31, 2007; and
18        (5) thereafter, the amount of energy efficiency and
19    demand-response measures implemented for any single year
20    shall be reduced by an amount necessary to limit the
21    estimated average net increase due to the cost of these
22    measures included in the amounts paid by eligible retail
23    customers in connection with electric service to no more
24    than the greater of 2.015% of the amount paid per
25    kilowatthour by those customers during the year ending May
26    31, 2007 or the incremental amount per kilowatthour paid

 

 

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1    for these measures in 2011.
2    No later than June 30, 2011, the Commission shall review
3the limitation on the amount of energy efficiency and
4demand-response measures implemented pursuant to this Section
5and report to the General Assembly its findings as to whether
6that limitation unduly constrains the procurement of energy
7efficiency and demand-response measures.
8    (e) Electric utilities shall be responsible for overseeing
9the design, development, and filing of energy efficiency and
10demand-response plans with the Commission. Electric utilities
11shall implement 100% of the demand-response measures in the
12plans. Electric utilities shall implement 75% of the energy
13efficiency measures approved by the Commission, and may, as
14part of that implementation, outsource various aspects of
15program development and implementation. The remaining 25% of
16those energy efficiency measures approved by the Commission
17shall be implemented by the Department of Commerce and Economic
18Opportunity, and must be designed in conjunction with the
19utility and the filing process. The Department may outsource
20development and implementation of energy efficiency measures.
21A minimum of 10% of the entire portfolio of cost-effective
22energy efficiency measures shall be procured from units of
23local government, municipal corporations, school districts,
24and community college districts. The Department shall
25coordinate the implementation of these measures.
26    The apportionment of the dollars to cover the costs to

 

 

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1implement the Department's share of the portfolio of energy
2efficiency measures shall be made to the Department once the
3Department has executed rebate agreements, grants, or
4contracts for energy efficiency measures and provided
5supporting documentation for those rebate agreements, grants,
6and contracts to the utility. The Department is authorized to
7adopt any rules necessary and prescribe procedures in order to
8ensure compliance by applicants in carrying out the purposes of
9rebate agreements for energy efficiency measures implemented
10by the Department made under this Section.
11    The details of the measures implemented by the Department
12shall be submitted by the Department to the Commission in
13connection with the utility's filing regarding the energy
14efficiency and demand-response measures that the utility
15implements.
16    A utility providing approved energy efficiency and
17demand-response measures in the State shall be permitted to
18recover costs of those measures through an automatic adjustment
19clause tariff filed with and approved by the Commission. The
20tariff shall be established outside the context of a general
21rate case. Each year the Commission shall initiate a review to
22reconcile any amounts collected with the actual costs and to
23determine the required adjustment to the annual tariff factor
24to match annual expenditures.
25    Each utility shall include, in its recovery of costs, the
26costs estimated for both the utility's and the Department's

 

 

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1implementation of energy efficiency and demand-response
2measures. Costs collected by the utility for measures
3implemented by the Department shall be submitted to the
4Department pursuant to Section 605-323 of the Civil
5Administrative Code of Illinois, shall be deposited into the
6Energy Efficiency Portfolio Standards Fund, and shall be used
7by the Department solely for the purpose of implementing these
8measures. A utility shall not be required to advance any moneys
9to the Department but only to forward such funds as it has
10collected. The Department shall report to the Commission on an
11annual basis regarding the costs actually incurred by the
12Department in the implementation of the measures. Any changes
13to the costs of energy efficiency measures as a result of plan
14modifications shall be appropriately reflected in amounts
15recovered by the utility and turned over to the Department.
16    The portfolio of measures, administered by both the
17utilities and the Department, shall, in combination, be
18designed to achieve the annual savings targets described in
19subsections (b) and (c) of this Section, as modified by
20subsection (d) of this Section.
21    The utility and the Department shall agree upon a
22reasonable portfolio of measures and determine the measurable
23corresponding percentage of the savings goals associated with
24measures implemented by the utility or Department.
25    No utility shall be assessed a penalty under subsection (f)
26of this Section for failure to make a timely filing if that

 

 

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1failure is the result of a lack of agreement with the
2Department with respect to the allocation of responsibilities
3or related costs or target assignments. In that case, the
4Department and the utility shall file their respective plans
5with the Commission and the Commission shall determine an
6appropriate division of measures and programs that meets the
7requirements of this Section.
8    If the Department is unable to meet incremental annual
9performance goals for the portion of the portfolio implemented
10by the Department, then the utility and the Department shall
11jointly submit a modified filing to the Commission explaining
12the performance shortfall and recommending an appropriate
13course going forward, including any program modifications that
14may be appropriate in light of the evaluations conducted under
15item (7) of subsection (f) of this Section. In this case, the
16utility obligation to collect the Department's costs and turn
17over those funds to the Department under this subsection (e)
18shall continue only if the Commission approves the
19modifications to the plan proposed by the Department.
20    (f) No later than November 15, 2007, each electric utility
21shall file an energy efficiency and demand-response plan with
22the Commission to meet the energy efficiency and
23demand-response standards for 2008 through 2010. No later than
24October 1, 2010, each electric utility shall file an energy
25efficiency and demand-response plan with the Commission to meet
26the energy efficiency and demand-response standards for 2011

 

 

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1through 2013. Every 3 years thereafter, each electric utility
2shall file, no later than September 1, an energy efficiency and
3demand-response plan with the Commission. If a utility does not
4file such a plan by September 1 of an applicable year, it shall
5face a penalty of $100,000 per day until the plan is filed.
6Each utility's plan shall set forth the utility's proposals to
7meet the utility's portion of the energy efficiency standards
8identified in subsection (b) and the demand-response standards
9identified in subsection (c) of this Section as modified by
10subsections (d) and (e), taking into account the unique
11circumstances of the utility's service territory. The
12Commission shall seek public comment on the utility's plan and
13shall issue an order approving or disapproving each plan within
145 months after its submission. If the Commission disapproves a
15plan, the Commission shall, within 30 days, describe in detail
16the reasons for the disapproval and describe a path by which
17the utility may file a revised draft of the plan to address the
18Commission's concerns satisfactorily. If the utility does not
19refile with the Commission within 60 days, the utility shall be
20subject to penalties at a rate of $100,000 per day until the
21plan is filed. This process shall continue, and penalties shall
22accrue, until the utility has successfully filed a portfolio of
23energy efficiency and demand-response measures. Penalties
24shall be deposited into the Energy Efficiency Trust Fund. In
25submitting proposed energy efficiency and demand-response
26plans and funding levels to meet the savings goals adopted by

 

 

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1this Act the utility shall:
2        (1) Demonstrate that its proposed energy efficiency
3    and demand-response measures will achieve the requirements
4    that are identified in subsections (b) and (c) of this
5    Section, as modified by subsections (d) and (e).
6        (2) Present specific proposals to implement new
7    building and appliance standards that have been placed into
8    effect.
9        (2.1) Include cost-effective heating and cooling
10    equipment capable of achieving an Energy Efficiency Rating
11    of at least 16.1 as calculated and determined by the most
12    recent Air-Conditioning, Heating, and Refrigeration
13    Institute certified ratings and listed in the Energy Star
14    program of the United States Environmental Protection
15    Agency.
16        (3) Present estimates of the total amount paid for
17    electric service expressed on a per kilowatthour basis
18    associated with the proposed portfolio of measures
19    designed to meet the requirements that are identified in
20    subsections (b) and (c) of this Section, as modified by
21    subsections (d) and (e).
22        (4) Coordinate with the Department to present a
23    portfolio of energy efficiency measures proportionate to
24    the share of total annual utility revenues in Illinois from
25    households at or below 150% of the poverty level. The
26    energy efficiency programs shall be targeted to households

 

 

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1    with incomes at or below 80% of area median income.
2        (5) Demonstrate that its overall portfolio of energy
3    efficiency and demand-response measures, not including
4    programs covered by item (4) of this subsection (f), are
5    cost-effective using the total resource cost test and
6    represent a diverse cross-section of opportunities for
7    customers of all rate classes to participate in the
8    programs.
9        (6) Include a proposed cost-recovery tariff mechanism
10    to fund the proposed energy efficiency and demand-response
11    measures and to ensure the recovery of the prudently and
12    reasonably incurred costs of Commission-approved programs.
13        (7) Provide for an annual independent evaluation of the
14    performance of the cost-effectiveness of the utility's
15    portfolio of measures and the Department's portfolio of
16    measures, as well as a full review of the 3-year results of
17    the broader net program impacts and, to the extent
18    practical, for adjustment of the measures on a
19    going-forward basis as a result of the evaluations. The
20    resources dedicated to evaluation shall not exceed 3% of
21    portfolio resources in any given year.
22    (g) No more than 3% of energy efficiency and
23demand-response program revenue may be allocated for
24demonstration of breakthrough equipment and devices.
25    (h) This Section does not apply to an electric utility that
26on December 31, 2005 provided electric service to fewer than

 

 

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1100,000 customers in Illinois.
2    (i) If, after 2 years, an electric utility fails to meet
3the efficiency standard specified in subsection (b) of this
4Section, as modified by subsections (d) and (e), it shall make
5a contribution to the Low-Income Home Energy Assistance
6Program. The combined total liability for failure to meet the
7goal shall be $1,000,000, which shall be assessed as follows: a
8large electric utility shall pay $665,000, and a medium
9electric utility shall pay $335,000. If, after 3 years, an
10electric utility fails to meet the efficiency standard
11specified in subsection (b) of this Section, as modified by
12subsections (d) and (e), it shall make a contribution to the
13Low-Income Home Energy Assistance Program. The combined total
14liability for failure to meet the goal shall be $1,000,000,
15which shall be assessed as follows: a large electric utility
16shall pay $665,000, and a medium electric utility shall pay
17$335,000. In addition, the responsibility for implementing the
18energy efficiency measures of the utility making the payment
19shall be transferred to the Illinois Power Agency if, after 3
20years, or in any subsequent 3-year period, the utility fails to
21meet the efficiency standard specified in subsection (b) of
22this Section, as modified by subsections (d) and (e). The
23Agency shall implement a competitive procurement program to
24procure resources necessary to meet the standards specified in
25this Section as modified by subsections (d) and (e), with costs
26for those resources to be recovered in the same manner as

 

 

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1products purchased through the procurement plan as provided in
2Section 16-111.5. The Director shall implement this
3requirement in connection with the procurement plan as provided
4in Section 16-111.5.
5    For purposes of this Section, (i) a "large electric
6utility" is an electric utility that, on December 31, 2005,
7served more than 2,000,000 electric customers in Illinois; (ii)
8a "medium electric utility" is an electric utility that, on
9December 31, 2005, served 2,000,000 or fewer but more than
10100,000 electric customers in Illinois; and (iii) Illinois
11electric utilities that are affiliated by virtue of a common
12parent company are considered a single electric utility.
13    (j) If, after 3 years, or any subsequent 3-year period, the
14Department fails to implement the Department's share of energy
15efficiency measures required by the standards in subsection
16(b), then the Illinois Power Agency may assume responsibility
17for and control of the Department's share of the required
18energy efficiency measures. The Agency shall implement a
19competitive procurement program to procure resources necessary
20to meet the standards specified in this Section, with the costs
21of these resources to be recovered in the same manner as
22provided for the Department in this Section.
23    (k) No electric utility shall be deemed to have failed to
24meet the energy efficiency standards to the extent any such
25failure is due to a failure of the Department or the Agency.
26(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09;

 

 

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196-1000, eff. 7-2-10; 97-616, eff. 10-26-11; 97-841, eff.
27-20-12.)
 
3    (220 ILCS 5/8-104)
4    Sec. 8-104. Natural gas energy efficiency programs.
5    (a) It is the policy of the State that natural gas
6utilities and the Department of Commerce and Economic
7Opportunity are required to use cost-effective energy
8efficiency to reduce direct and indirect costs to consumers. It
9serves the public interest to allow natural gas utilities to
10recover costs for reasonably and prudently incurred expenses
11for cost-effective energy efficiency measures.
12    (b) For purposes of this Section, "energy efficiency" means
13measures that reduce the amount of energy required to achieve a
14given end use. "Energy efficiency" also includes measures that
15reduce the total Btus of electricity and natural gas needed to
16meet the end use or uses. "Cost-effective" and "cost-effective"
17means that the measures satisfy the total resource cost test
18which, for purposes of this Section, means a standard that is
19met if, for an investment in energy efficiency, the
20benefit-cost ratio is greater than one. The benefit-cost ratio
21is the ratio of the net present value of the total benefits of
22the measures to the net present value of the total costs as
23calculated over the lifetime of the measures. The total
24resource cost test compares the sum of avoided natural gas
25utility costs, representing the benefits that accrue to the

 

 

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1system and the participant in the delivery of those efficiency
2measures, as well as other quantifiable societal benefits,
3including avoided electric utility costs, to the sum of all
4incremental costs of end use measures (including both utility
5and participant contributions), plus costs to administer,
6deliver, and evaluate each demand-side measure, to quantify the
7net savings obtained by substituting demand-side measures for
8supply resources. In calculating avoided costs, reasonable
9estimates shall be included for financial costs likely to be
10imposed by future regulation of emissions of greenhouse gases.
11The low-income programs described in item (4) of subsection (f)
12of this Section shall not be required to meet the total
13resource cost test.
14    (c) Natural gas utilities shall implement cost-effective
15energy efficiency measures to meet at least the following
16natural gas savings requirements, which shall be based upon the
17total amount of gas delivered to retail customers, other than
18the customers described in subsection (m) of this Section,
19during calendar year 2009 multiplied by the applicable
20percentage. Natural gas utilities may comply with this Section
21by meeting the annual incremental savings goal in the
22applicable year or by showing that total savings associated
23with measures implemented after May 31, 2011 were equal to the
24sum of each annual incremental savings requirement from May 31,
252011 through the end of the applicable year:
26        (1) 0.2% by May 31, 2012;

 

 

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1        (2) an additional 0.4% by May 31, 2013, increasing
2    total savings to .6%;
3        (3) an additional 0.6% by May 31, 2014, increasing
4    total savings to 1.2%;
5        (4) an additional 0.8% by May 31, 2015, increasing
6    total savings to 2.0%;
7        (5) an additional 1% by May 31, 2016, increasing total
8    savings to 3.0%;
9        (6) an additional 1.2% by May 31, 2017, increasing
10    total savings to 4.2%;
11        (7) an additional 1.4% by May 31, 2018, increasing
12    total savings to 5.6%;
13        (8) an additional 1.5% by May 31, 2019, increasing
14    total savings to 7.1%; and
15        (9) an additional 1.5% in each 12-month period
16    thereafter.
17    (d) Notwithstanding the requirements of subsection (c) of
18this Section, a natural gas utility shall limit the amount of
19energy efficiency implemented in any 3-year reporting period
20established by subsection (f) of Section 8-104 of this Act, by
21an amount necessary to limit the estimated average increase in
22the amounts paid by retail customers in connection with natural
23gas service to no more than 2% in the applicable 3-year
24reporting period. The energy savings requirements in
25subsection (c) of this Section may be reduced by the Commission
26for the subject plan, if the utility demonstrates by

 

 

09800SB2365sam001- 32 -LRB098 06614 CEL 44689 a

1substantial evidence that it is highly unlikely that the
2requirements could be achieved without exceeding the
3applicable spending limits in any 3-year reporting period. No
4later than September 1, 2013, the Commission shall review the
5limitation on the amount of energy efficiency measures
6implemented pursuant to this Section and report to the General
7Assembly, in the report required by subsection (k) of this
8Section, its findings as to whether that limitation unduly
9constrains the procurement of energy efficiency measures.
10    (e) Natural gas utilities shall be responsible for
11overseeing the design, development, and filing of their
12efficiency plans with the Commission. The utility shall utilize
1375% of the available funding associated with energy efficiency
14programs approved by the Commission, and may outsource various
15aspects of program development and implementation. The
16remaining 25% of available funding shall be used by the
17Department of Commerce and Economic Opportunity to implement
18energy efficiency measures that achieve no less than 20% of the
19requirements of subsection (c) of this Section. Such measures
20shall be designed in conjunction with the utility and approved
21by the Commission. The Department may outsource development and
22implementation of energy efficiency measures. A minimum of 10%
23of the entire portfolio of cost-effective energy efficiency
24measures shall be procured from local government, municipal
25corporations, school districts, and community college
26districts. Five percent of the entire portfolio of

 

 

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1cost-effective energy efficiency measures may be granted to
2local government and municipal corporations for market
3transformation initiatives. The Department shall coordinate
4the implementation of these measures and shall integrate
5delivery of natural gas efficiency programs with electric
6efficiency programs delivered pursuant to Section 8-103 of this
7Act, unless the Department can show that integration is not
8feasible.
9    The apportionment of the dollars to cover the costs to
10implement the Department's share of the portfolio of energy
11efficiency measures shall be made to the Department once the
12Department has executed rebate agreements, grants, or
13contracts for energy efficiency measures and provided
14supporting documentation for those rebate agreements, grants,
15and contracts to the utility. The Department is authorized to
16adopt any rules necessary and prescribe procedures in order to
17ensure compliance by applicants in carrying out the purposes of
18rebate agreements for energy efficiency measures implemented
19by the Department made under this Section.
20    The details of the measures implemented by the Department
21shall be submitted by the Department to the Commission in
22connection with the utility's filing regarding the energy
23efficiency measures that the utility implements.
24    A utility providing approved energy efficiency measures in
25this State shall be permitted to recover costs of those
26measures through an automatic adjustment clause tariff filed

 

 

09800SB2365sam001- 34 -LRB098 06614 CEL 44689 a

1with and approved by the Commission. The tariff shall be
2established outside the context of a general rate case and
3shall be applicable to the utility's customers other than the
4customers described in subsection (m) of this Section. Each
5year the Commission shall initiate a review to reconcile any
6amounts collected with the actual costs and to determine the
7required adjustment to the annual tariff factor to match annual
8expenditures.
9    Each utility shall include, in its recovery of costs, the
10costs estimated for both the utility's and the Department's
11implementation of energy efficiency measures. Costs collected
12by the utility for measures implemented by the Department shall
13be submitted to the Department pursuant to Section 605-323 of
14the Civil Administrative Code of Illinois, shall be deposited
15into the Energy Efficiency Portfolio Standards Fund, and shall
16be used by the Department solely for the purpose of
17implementing these measures. A utility shall not be required to
18advance any moneys to the Department but only to forward such
19funds as it has collected. The Department shall report to the
20Commission on an annual basis regarding the costs actually
21incurred by the Department in the implementation of the
22measures. Any changes to the costs of energy efficiency
23measures as a result of plan modifications shall be
24appropriately reflected in amounts recovered by the utility and
25turned over to the Department.
26    The portfolio of measures, administered by both the

 

 

09800SB2365sam001- 35 -LRB098 06614 CEL 44689 a

1utilities and the Department, shall, in combination, be
2designed to achieve the annual energy savings requirements set
3forth in subsection (c) of this Section, as modified by
4subsection (d) of this Section.
5    The utility and the Department shall agree upon a
6reasonable portfolio of measures and determine the measurable
7corresponding percentage of the savings goals associated with
8measures implemented by the Department.
9    No utility shall be assessed a penalty under subsection (f)
10of this Section for failure to make a timely filing if that
11failure is the result of a lack of agreement with the
12Department with respect to the allocation of responsibilities
13or related costs or target assignments. In that case, the
14Department and the utility shall file their respective plans
15with the Commission and the Commission shall determine an
16appropriate division of measures and programs that meets the
17requirements of this Section.
18    If the Department is unable to meet performance
19requirements for the portion of the portfolio implemented by
20the Department, then the utility and the Department shall
21jointly submit a modified filing to the Commission explaining
22the performance shortfall and recommending an appropriate
23course going forward, including any program modifications that
24may be appropriate in light of the evaluations conducted under
25item (8) of subsection (f) of this Section. In this case, the
26utility obligation to collect the Department's costs and turn

 

 

09800SB2365sam001- 36 -LRB098 06614 CEL 44689 a

1over those funds to the Department under this subsection (e)
2shall continue only if the Commission approves the
3modifications to the plan proposed by the Department.
4    (f) No later than October 1, 2010, each gas utility shall
5file an energy efficiency plan with the Commission to meet the
6energy efficiency standards through May 31, 2014. Every 3 years
7thereafter, each utility shall file, no later than October 1,
8an energy efficiency plan with the Commission. If a utility
9does not file such a plan by October 1 of the applicable year,
10then it shall face a penalty of $100,000 per day until the plan
11is filed. Each utility's plan shall set forth the utility's
12proposals to meet the utility's portion of the energy
13efficiency standards identified in subsection (c) of this
14Section, as modified by subsection (d) of this Section, taking
15into account the unique circumstances of the utility's service
16territory. The Commission shall seek public comment on the
17utility's plan and shall issue an order approving or
18disapproving each plan. If the Commission disapproves a plan,
19the Commission shall, within 30 days, describe in detail the
20reasons for the disapproval and describe a path by which the
21utility may file a revised draft of the plan to address the
22Commission's concerns satisfactorily. If the utility does not
23refile with the Commission within 60 days after the
24disapproval, the utility shall be subject to penalties at a
25rate of $100,000 per day until the plan is filed. This process
26shall continue, and penalties shall accrue, until the utility

 

 

09800SB2365sam001- 37 -LRB098 06614 CEL 44689 a

1has successfully filed a portfolio of energy efficiency
2measures. Penalties shall be deposited into the Energy
3Efficiency Trust Fund and the cost of any such penalties may
4not be recovered from ratepayers. In submitting proposed energy
5efficiency plans and funding levels to meet the savings goals
6adopted by this Act the utility shall:
7        (1) Demonstrate that its proposed energy efficiency
8    measures will achieve the requirements that are identified
9    in subsection (c) of this Section, as modified by
10    subsection (d) of this Section.
11        (2) Present specific proposals to implement new
12    building and appliance standards that have been placed into
13    effect.
14        (3) Present estimates of the total amount paid for gas
15    service expressed on a per therm basis associated with the
16    proposed portfolio of measures designed to meet the
17    requirements that are identified in subsection (c) of this
18    Section, as modified by subsection (d) of this Section.
19        (4) Coordinate with the Department to present a
20    portfolio of energy efficiency measures proportionate to
21    the share of total annual utility revenues in Illinois from
22    households at or below 150% of the poverty level. Such
23    programs shall be targeted to households with incomes at or
24    below 80% of area median income.
25        (5) Demonstrate that its overall portfolio of energy
26    efficiency measures, not including programs covered by

 

 

09800SB2365sam001- 38 -LRB098 06614 CEL 44689 a

1    item (4) of this subsection (f), are cost-effective using
2    the total resource cost test and represent a diverse cross
3    section of opportunities for customers of all rate classes
4    to participate in the programs.
5        (6) Demonstrate that a gas utility affiliated with an
6    electric utility that is required to comply with Section
7    8-103 of this Act has integrated gas and electric
8    efficiency measures into a single program that reduces
9    program or participant costs and appropriately allocates
10    costs to gas and electric ratepayers. The Department shall
11    integrate all gas and electric programs it delivers in any
12    such utilities' service territories, unless the Department
13    can show that integration is not feasible or appropriate.
14        (7) Include a proposed cost recovery tariff mechanism
15    to fund the proposed energy efficiency measures and to
16    ensure the recovery of the prudently and reasonably
17    incurred costs of Commission-approved programs.
18        (8) Provide for quarterly status reports tracking
19    implementation of and expenditures for the utility's
20    portfolio of measures and the Department's portfolio of
21    measures, an annual independent review, and a full
22    independent evaluation of the 3-year results of the
23    performance and the cost-effectiveness of the utility's
24    and Department's portfolios of measures and broader net
25    program impacts and, to the extent practical, for
26    adjustment of the measures on a going forward basis as a

 

 

09800SB2365sam001- 39 -LRB098 06614 CEL 44689 a

1    result of the evaluations. The resources dedicated to
2    evaluation shall not exceed 3% of portfolio resources in
3    any given 3-year period.
4    (g) No more than 3% of expenditures on energy efficiency
5measures may be allocated for demonstration of breakthrough
6equipment and devices.
7    (h) Illinois natural gas utilities that are affiliated by
8virtue of a common parent company may, at the utilities'
9request, be considered a single natural gas utility for
10purposes of complying with this Section.
11    (i) If, after 3 years, a gas utility fails to meet the
12efficiency standard specified in subsection (c) of this Section
13as modified by subsection (d), then it shall make a
14contribution to the Low-Income Home Energy Assistance Program.
15The total liability for failure to meet the goal shall be
16assessed as follows:
17        (1) a large gas utility shall pay $600,000;
18        (2) a medium gas utility shall pay $400,000; and
19        (3) a small gas utility shall pay $200,000.
20    For purposes of this Section, (i) a "large gas utility" is
21a gas utility that on December 31, 2008, served more than
221,500,000 gas customers in Illinois; (ii) a "medium gas
23utility" is a gas utility that on December 31, 2008, served
24fewer than 1,500,000, but more than 500,000 gas customers in
25Illinois; and (iii) a "small gas utility" is a gas utility that
26on December 31, 2008, served fewer than 500,000 and more than

 

 

09800SB2365sam001- 40 -LRB098 06614 CEL 44689 a

1100,000 gas customers in Illinois. The costs of this
2contribution may not be recovered from ratepayers.
3    If a gas utility fails to meet the efficiency standard
4specified in subsection (c) of this Section, as modified by
5subsection (d) of this Section, in any 2 consecutive 3-year
6planning periods, then the responsibility for implementing the
7utility's energy efficiency measures shall be transferred to an
8independent program administrator selected by the Commission.
9Reasonable and prudent costs incurred by the independent
10program administrator to meet the efficiency standard
11specified in subsection (c) of this Section, as modified by
12subsection (d) of this Section, may be recovered from the
13customers of the affected gas utilities, other than customers
14described in subsection (m) of this Section. The utility shall
15provide the independent program administrator with all
16information and assistance necessary to perform the program
17administrator's duties including but not limited to customer,
18account, and energy usage data, and shall allow the program
19administrator to include inserts in customer bills. The utility
20may recover reasonable costs associated with any such
21assistance.
22    (j) No utility shall be deemed to have failed to meet the
23energy efficiency standards to the extent any such failure is
24due to a failure of the Department.
25    (k) Not later than January 1, 2012, the Commission shall
26develop and solicit public comment on a plan to foster

 

 

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1statewide coordination and consistency between statutorily
2mandated natural gas and electric energy efficiency programs to
3reduce program or participant costs or to improve program
4performance. Not later than September 1, 2013, the Commission
5shall issue a report to the General Assembly containing its
6findings and recommendations.
7    (l) This Section does not apply to a gas utility that on
8January 1, 2009, provided gas service to fewer than 100,000
9customers in Illinois.
10    (m) Subsections (a) through (k) of this Section do not
11apply to customers of a natural gas utility that have a North
12American Industry Classification System code number that is
1322111 or any such code number beginning with the digits 31, 32,
14or 33 and (i) annual usage in the aggregate of 4 million therms
15or more within the service territory of the affected gas
16utility or with aggregate usage of 8 million therms or more in
17this State and complying with the provisions of item (l) of
18this subsection (m); or (ii) using natural gas as feedstock and
19meeting the usage requirements described in item (i) of this
20subsection (m), to the extent such annual feedstock usage is
21greater than 60% of the customer's total annual usage of
22natural gas.
23        (1) Customers described in this subsection (m) of this
24    Section shall apply, on a form approved on or before
25    October 1, 2009 by the Department, to the Department to be
26    designated as a self-directing customer ("SDC") or as an

 

 

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1    exempt customer using natural gas as a feedstock from which
2    other products are made, including, but not limited to,
3    feedstock for a hydrogen plant, on or before the 1st day of
4    February, 2010. Thereafter, application may be made not
5    less than 6 months before the filing date of the gas
6    utility energy efficiency plan described in subsection (f)
7    of this Section; however, a new customer that commences
8    taking service from a natural gas utility after February 1,
9    2010 may apply to become a SDC or exempt customer up to 30
10    days after beginning service. Such application shall
11    contain the following:
12            (A) the customer's certification that, at the time
13        of its application, it qualifies to be a SDC or exempt
14        customer described in this subsection (m) of this
15        Section;
16            (B) in the case of a SDC, the customer's
17        certification that it has established or will
18        establish by the beginning of the utility's 3-year
19        planning period commencing subsequent to the
20        application, and will maintain for accounting
21        purposes, an energy efficiency reserve account and
22        that the customer will accrue funds in said account to
23        be held for the purpose of funding, in whole or in
24        part, energy efficiency measures of the customer's
25        choosing, which may include, but are not limited to,
26        projects involving combined heat and power systems

 

 

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1        that use the same energy source both for the generation
2        of electrical or mechanical power and the production of
3        steam or another form of useful thermal energy or the
4        use of combustible gas produced from biomass, or both;
5            (C) in the case of a SDC, the customer's
6        certification that annual funding levels for the
7        energy efficiency reserve account will be equal to 2%
8        of the customer's cost of natural gas, composed of the
9        customer's commodity cost and the delivery service
10        charges paid to the gas utility, or $150,000, whichever
11        is less;
12            (D) in the case of a SDC, the customer's
13        certification that the required reserve account
14        balance will be capped at 3 years' worth of accruals
15        and that the customer may, at its option, make further
16        deposits to the account to the extent such deposit
17        would increase the reserve account balance above the
18        designated cap level;
19            (E) in the case of a SDC, the customer's
20        certification that by October 1 of each year, beginning
21        no sooner than October 1, 2012, the customer will
22        report to the Department information, for the 12-month
23        period ending May 31 of the same year, on all deposits
24        and reductions, if any, to the reserve account during
25        the reporting year, and to the extent deposits to the
26        reserve account in any year are in an amount less than

 

 

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1        $150,000, the basis for such reduced deposits; reserve
2        account balances by month; a description of energy
3        efficiency measures undertaken by the customer and
4        paid for in whole or in part with funds from the
5        reserve account; an estimate of the energy saved, or to
6        be saved, by the measure; and that the report shall
7        include a verification by an officer or plant manager
8        of the customer or by a registered professional
9        engineer or certified energy efficiency trade
10        professional that the funds withdrawn from the reserve
11        account were used for the energy efficiency measures;
12            (F) in the case of an exempt customer, the
13        customer's certification of the level of gas usage as
14        feedstock in the customer's operation in a typical year
15        and that it will provide information establishing this
16        level, upon request of the Department;
17            (G) in the case of either an exempt customer or a
18        SDC, the customer's certification that it has provided
19        the gas utility or utilities serving the customer with
20        a copy of the application as filed with the Department;
21            (H) in the case of either an exempt customer or a
22        SDC, certification of the natural gas utility or
23        utilities serving the customer in Illinois including
24        the natural gas utility accounts that are the subject
25        of the application; and
26            (I) in the case of either an exempt customer or a

 

 

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1        SDC, a verification signed by a plant manager or an
2        authorized corporate officer attesting to the
3        truthfulness and accuracy of the information contained
4        in the application.
5        (2) The Department shall review the application to
6    determine that it contains the information described in
7    provisions (A) through (I) of item (1) of this subsection
8    (m), as applicable. The review shall be completed within 30
9    days after the date the application is filed with the
10    Department. Absent a determination by the Department
11    within the 30-day period, the applicant shall be considered
12    to be a SDC or exempt customer, as applicable, for all
13    subsequent 3-year planning periods, as of the date of
14    filing the application described in this subsection (m). If
15    the Department determines that the application does not
16    contain the applicable information described in provisions
17    (A) through (I) of item (1) of this subsection (m), it
18    shall notify the customer, in writing, of its determination
19    that the application does not contain the required
20    information and identify the information that is missing,
21    and the customer shall provide the missing information
22    within 15 working days after the date of receipt of the
23    Department's notification.
24        (3) The Department shall have the right to audit the
25    information provided in the customer's application and
26    annual reports to ensure continued compliance with the

 

 

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1    requirements of this subsection. Based on the audit, if the
2    Department determines the customer is no longer in
3    compliance with the requirements of items (A) through (I)
4    of item (1) of this subsection (m), as applicable, the
5    Department shall notify the customer in writing of the
6    noncompliance. The customer shall have 30 days to establish
7    its compliance, and failing to do so, may have its status
8    as a SDC or exempt customer revoked by the Department. The
9    Department shall treat all information provided by any
10    customer seeking SDC status or exemption from the
11    provisions of this Section as strictly confidential.
12        (4) Upon request, or on its own motion, the Commission
13    may open an investigation, no more than once every 3 years
14    and not before October 1, 2014, to evaluate the
15    effectiveness of the self-directing program described in
16    this subsection (m).
17    (n) The applicability of this Section to customers
18described in subsection (m) of this Section is conditioned on
19the existence of the SDC program. In no event will any
20provision of this Section apply to such customers after January
211, 2020.
22(Source: P.A. 96-33, eff. 7-10-09; 97-813, eff. 7-13-12;
2397-841, eff. 7-20-12.)
 
24    Section 99. Effective date. This Act takes effect upon
25becoming law.".